Methods and apparatus for measuring flow velocity in a wellbore using NMR and applications using same

ABSTRACT

The present invention provides methods and apparatus for determining flow velocity within a formation utilizing nuclear magnetic resonance (NMR) techniques in which the shape of the resonance region is restricted so that sensitivity to radial flow or vertical flow is obtained (or both when more than one NMR tool is used). Flow velocity using these NMR tools is determined using decay amplitude, frequency displacement or stimulated echoes (where the spins are stored along the magnetic field instead of the transverse plane to exploit echo decays and frequency displacements) based on the application of adiabatic pulses. Based on the described NMR measurement of flow velocity, additional wellbore parameters may be obtained such as a direct measurement of permeability, an assessment of drilling damage to the wellbore, formation pressure, invasion rate of the mud filtrate or the migration of fine mud particles during sampling operations.

This is a division of U.S. patent application Ser. No. 09/951,914, filedSep. 10, 2001 now U.S. Pat. No. 6,528,995.

FIELD OF THE INVENTION

This invention relates to the field of well logging of earth wellboresand, more particularly, to methods for measuring flow velocity in anearth formation with nuclear magnetic resonance techniques and for usingthe measured flow velocity to determine various other important welllogging parameters.

BACKGROUND OF THE INVENTION

Well logging provides various parameters that may be used to determinethe “quality” of a formation from a given wellbore. These parametersinclude such factors as: formation pressure, resistivity, porosity,bound fluid volume and hydraulic permeability. These parameters, whichare used to evaluate the quality of a given formation, may provide, forexample, the amount of hydrocarbons present within the formation, aswell as an indication as to the difficulty in extracting thosehydrocarbons from the formation. Hydraulic permeability—how easily thehydrocarbons will flow through the pores of the formation—is therefore,an important factor in determining whether a specific well site iscommercially viable.

There are various known techniques for determining hydraulicpermeability, as well as other well logging parameters. For example, itis known how to derive permeability from nuclear magnetic resonance(NMR) measurements. NMR measurements, in general, are accomplished bycausing the magnetic moments of nuclei in a formation to precess aboutan axis. The axis about which the nuclei precess may be established byapplying a strong, polarizing, static magnetic field (B_(O)) to theformation, such as through the use of permanent magnets (i.e.,polarization). This field causes the proton spins to align in adirection parallel to the applied field (this step, which is sometimesreferred to as longitudinal magnetization, results in the nuclei being“polarized”). Polarization does not occur immediately, but instead growsin accordance with a time constant T_(l), as described more fully below,and may take as long as several seconds to occur (even up to about eightseconds or longer). After sufficient time, a thermal equilibriumpolarization parallel to B_(O) has been established.

Next, a series of radio frequency (RF) pulses are produced so that anoscillating magnetic field B_(l) is applied. The first RF pulse(referred to as the 90° pulse) must be strong enough to rotate themagnetization from B_(O) substantially into the transverse plane (i.e.,transverse magnetization). The rotation angle is given by:

α=B₁γt_(p)  (1)

and is adjusted, by methods known to those skilled in the art, to be 90°(where t_(p) is the pulse length and γ is the gyromagnetic ratio—anuclear constant). Additional RF pulses (referred to as 180° pulseswhere α=180°) are applied to create a series of spin echoes. Theadditional RF pulses typically are applied in accordance with a pulsesquence, such as the error-correcting CPMG (Carr-Purcell-Meiboom-Gill)NMR pulse sequence, to facilitate rapid and accurate data collection.The frequency of the RF pulses is chosen to excite specific nuclearspins in the particular region of the sample that is being investigated.The rotation angles of the RF pulses are adjusted to be 90° and 180° inthe center of this region.

Two time constants are associated with the relaxation process of thelongitudinal and transverse magnetization. These time constantscharacterize the rate of return to thermal equilibrium of themagnetization components following the application of each 90° pulse.The spin-lattice relaxation time (T₁) is the time constant for thelongitudinal magnetization component to return to its thermalequilibrium (after the application of the static magnetic field). Thespin—spin relaxation time (T₂) is the time constant for the transversemagnetization to return to its thermal equilibrium value which is zero.Typically, T₂ distributions are measured using a pulse sequence such asthe CMPG pulse sequence described above. In addition, B_(O) is typicallyinhomogeneous and the transverse magnetization decays with the shortertime constant T₂*, where: $\begin{matrix}{\frac{1}{T_{2}^{*}} = {\frac{1}{T_{2}} + \frac{1}{T^{\prime}}}} & (2)\end{matrix}$

In the absence of motion and diffusion, the decay with characteristictime T′ is due to B_(O) inhomogeneities alone. In this case, it iscompletely reversible and can be recovered in successive echoes. Theamplitudes of successive echoes decay with T₂. Upon obtaining the T₂distributions, other formation characteristics, such as permeability,may be determined.

A potential problem with the T₂ distributions may occur if the echodecays faster than predicted, for example, if motion of the measuringprobe occurs during measurements. Under these conditions, the resultantdata may be degraded. Thus, for example, displacement of the measurementdevice due to fast logging speed, rough wellbore conditions orvibrations of the drill string during logging-while-drilling (LWD) mayprevent accurate measurements from being obtained.

Moreover, it also is known that T₂ distributions do not alwaysaccurately represent pore size. For example, G. R. Coates et al., “A NewCharacterization of Bulk-Volume Irreducible Using Magnetic Resonance,”SPWLA 38th Annual Logging Symposium, Jun. 15-18, 1997, describes themeasurement of bound fluid volume by relating each relaxation time to aspecific fraction of capillary bound water. This method assumes thateach pore size has an inherent irreducible water saturation (i.e.,regardless of pore size, some water will always be trapped within thepores). In addition, the presence of hydrocarbons in water wet rockschanges the correlation between the T₂ distribution and pore size.

Hydraulic permeability of the formation is one of the most importantcharacteristics of a hydrocarbon reservoir and one of the most difficultquantitative measurements to obtain. Often permeability is derived fromT₂ distributions, created from NMR experiments, which represent poresize distributions. Finally, permeability is related to the T₂ data.This way to determine permeability has several drawbacks and istherefore sometimes inapplicable.

Typically T₂ distributions are measured using the error-correcting CPMGpulse sequence. In order to provide meaningful results, the length ofthe recorded echo train must be at least T₂ ^(max). During this timeperiod, as well as during the preceding prepolarization period, themeasurement is sensitive to displacements of the measuring device.Further, in some cases, the T₂ distributions do not represent pore sizedistributions, e.g., hydrocarbons in water wet rocks change thecorrelation between T₂ distribution and pore size distribution. Finally,the correlation between pore size distribution and permeability of theformation is achieved using several phenomenological formulae that arebased on large measured data sets, displaying relatively weakcorrelation. In carbonates, these formulae breakdown because of theformations' complex pore shapes.

A more direct way to measure permeability is by measurements of inducedflow rates using a packer or probe tool. Still, this measurementrequires extensive modeling of the formation response which includes thegeometry of the reservoir and of the tool, the mud cake, and theinvasion zone. The effort required for modeling however, could besignificantly reduced if flow velocity could be obtained. It would beadvantageous to obtain flow velocity, which could be used to determinevarious parameters required for modeling so that the number of variablesrequired for modeling is reduced.

For at least the foregoing reasons, it is an object of the presentinvention to provide apparatus and methods for determining flow velocityutilizing NMR techniques.

It is a still further object of the present invention to provide methodsfor determining permeability utilizing NMR measurements of flowvelocity.

It is an even further object of the present invention to provide methodsfor determining the extent of drilling damage to the formation,formation pressure, mud filtration rate and changes in the invaded zoneduring sampling utilizing NMR measurements of flow velocity.

SUMMARY OF THE INVENTION

These and other objects of the invention are accomplished in accordancewith the principles of the invention by providing methods and apparatusfor determining flow velocity utilizing nuclear magnetic resonance (NMR)techniques and for providing measurements of other wellbore parametersbased on the flow velocity measurements. The preferred embodimentsinclude methods and apparatus in which flow velocity is determinedwithout knowledge of T₂ or the pressure distribution. The flow velocitymeasurements are made using NMR techniques in which the shape of theresonance region is varied depending on whether radial or verticalsensitivity is desired. In an embodiment that requires knowledge of T₂,the decay of the echo amplitude is measured. If both radial and verticalsensitivity are desired, multiple NMR devices may be provided in asingle wellbore tool where each NMR device is designed to measure aspecific orientation.

In other preferred embodiments of the present invention, NMRdetermination of frequency displacement, rather than signal decay, isutilized to determine flow velocity. An advantage of these techniquesalso is that no reference measurements need be taken because thedetection of signal decay is not employed. This can be achieved byanalyzing the echo shape instead of the echo amplitude or by standardNMR one-dimensional frequency selective or two-dimensional methods. Instill other preferred embodiments, an encoding pulse is substituted forthe traditional 90° pulse, and adiabatic pulses are substituted for thetraditional 180° pulses. These techniques are advantageous if the B_(O)gradient is small, e.g., in the case of a B_(O) saddle point, becauseonly an inhomogeneous field B₁ is required, rather than a B_(O)gradient.

The methods and apparatus of the present invention for obtaining flowvelocity using NMR techniques also are applicable to determining variouswellbore parameters during wellbore drilling operations. For example, byinducing fluid to flow within the formation such as by withdrawing fluidfrom the formation into the NMR tool or into the wellbore, the NMRdetermination of flow velocity may be used in conjunction with adifferential pressure measurement to provide a direct, small-scalemeasurement of permeability due to the fact that the NMR data providesan extremely localized measurement of fluid velocity. Alternatively, theNMR techniques of the present invention may be used to obtain anassessment of the drilling damage to the formation.

In addition, the NMR techniques of the present invention may be used todetermine formation pressure by establishing conditions in the wellbore(for example, by using a packer module) such that no filtration ofwellbore fluid occurs across the mudcake and simultaneously measuringthe pressure at the interface between the mudcake and the formation.Another important parameter that may be determined using the NMRtechniques of the present invention is mud filtration rate (sometimesreferred to as invasion). This parameter may be particularly importantbecause it provides a direct measure of the quality of the mud systembeing employed and may provide an advance indication of potentialproblems. Also, the NMR techniques of the present invention may be usedto monitor changes in the invaded zone during sampling operations. Undersuch conditions, it is often important to monitor the migration of finemud particles (or “fines”) that may give rise to plugging of theformation where the sampling is being conducted. Moreover, while thedetermination of various operational parameters is described herein,persons skilled in the art will appreciate that various other parametersmay be obtained utilizing the NMR techniques of the present invention.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of one embodiment of an NMR loggingapparatus for measuring flow velocity in accordance with the principlesof the present invention;

FIG. 2a is a plan-view schematic representation of one embodiment of anNMR tool component that may be utilized in conjunction with the NMRlogging apparatus of FIG. 1 in accordance with the principles of thepresent invention;

FIG. 2b is a cross-sectional-view schematic representation of oneembodiment of an NMR tool component that may be utilized in conjunctionwith the NMR logging apparatus of FIG. 1 in accordance with theprinciples of the present invention;

FIG. 3a is a plan-view schematic representation of another embodiment ofan NMR tool component that may be utilized in conjunction with the NMRlogging apparatus of FIG. 1 in accordance with the principles of thepresent invention;

FIG. 3b is a cross-sectional-view schematic representation of anotherembodiment of an NMR tool component that may be utilized in conjunctionwith the NMR logging apparatus of FIG. 1 in accordance with theprinciples of the present invention;

FIG. 4 is a side-view schematic representation of one embodiment of apressure measurement tool component that may be used in conjunction withthe NMR tool components of FIGS. 2 and 3 in accordance with theprinciples of the present invention;

FIG. 5 is a schematic diagram of another embodiment of an NMR loggingapparatus in accordance with the principles of the present invention;

FIGS. 6a-e are schematic examples of acquired exchange distribution andthe effects of frequency displacement for a given echo in accordancewith the present invention;

FIG. 7 is a flow chart illustrating steps for determining flow velocityin accordance with the principles of the present invention; and

FIG. 8 is a pulse sequence illustrating the use of adiabatic pulseechoes in accordance with the present invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The methods and apparatus of the present invention utilize severaltechniques to determine various qualitative parameters regarding a givenformation from NMR measurements. The initial techniques provide ameasurement of formation fluid speed (i.e., flow velocity) that leads toa determination of formation pressure and/or mud filtration rate. Toaccomplish these techniques, the NMR tool must include the ability toinduce flow in the formation (one tool component) and to create an NMRshell in the formation that is used to measure the induced flow (asecond tool component). When the basic techniques described herein aresupplemented by measurements of local pressure gradient (e.g., by addinga third tool component to the drill string), the techniques of thepresent invention may also provide a determination of permeabilityand/or skin damage (i.e., the area between the wellbore and the virginformation).

Described herein are various ways to induce fluid to flow within thewellbore in conjunction with the determination of flow velocity. Forexample, during drilling, the pressure in the wellbore fluid may bechanged via an external device such as a rig pump. Alternatively, a toolsuch as that shown in FIG. 1 and described below may be deployed(drilling would not be occurring under these circumstances) that pumpsfluid into or withdraws it from the packer interval. Still another wayto induce fluid flow is through the use of a port located on a pad, suchas that shown in FIGS. 3a and 3 b and described below, in which casefluid would again be pumped into or out of the tool.

Various known techniques exist for determining flow velocity. Forexample, NMR techniques may utilize switched gradients to encode flowand diffusion. However, under certain circumstances switched gradientsmay be difficult, if not impossible, to produce, and in the presence oflarge static gradients, they may be negligible. The echo measurements ofthe present invention can be produced such that they rely only on staticgradient B_(O) or B₁ fields instead of switched gradients, andtherefore, it works for “inside out” NMR conditions where measurementsare made outside the magnet configuration.

FIG. 1 shows an illustrative example of an NMR logging device 100 thatmeasures flow velocity. Logging device 100 includes four modulesincluding: packer 102, NMR tool 104, packer 106 and NMR tool 108. Whilelogging device 100 is shown having four modules, persons skilled in theart will appreciate that various other combinations of logging tools maybe used, including other known logging tools that are not mentionedherein. For example, logging device 100 may be used without NMR tool108, in which case device 100 only would have three modules.

As shown in FIG. 1, logging device 100 is located in wellbore 110 thatpreviously has been drilled in earth formation 112. Logging device 100is suspended in wellbore 110 from logging cable 114. It is withincontemplation of this invention for the logging device 100 to beconveyed in the wellbore by drill pipe or coiled tubing. As described inmore detail below, the principles of the present invention also may beapplied to logging-while-drilling (LWD) operations, in which caselogging device 100 (or the applicable modules (e.g., packers)) thenwould be located within a drill string (not shown) behind the drill bit(not shown). Also shown in FIG. 1 are flow lines 116, and resonancelines 118 and 120 that are explained in more detail below.

It is known that a net displacement of a resonated substance withrespect to its spatial position in the field maps of the measuringdevice at the moment of excitation by a pulse sequence leads to adecreased decay amplitude (DA) in the measured signal amplitude A. Thisdisplacement may be a product of actual displacement, translationaldiffusion or a combination of both. Normal NMR multi-echo experimentscorrect to a high degree for diffusion, so that given sufficiently shortecho spacing only the total displacement due to diffusion at detectiontime is important. Directed flow, however, can be detected even in thepresence of diffusion as long as the displacement due to flow is atleast comparable to the displacement due to diffusion.

The loss of the I-th echo can be characterized by a loss factor:λ_(i)=λ_(i)/λ⁰ _(i), where λ⁰ _(i) is the amplitude of the I-th echounder the same circumstances except for no displacement. Importantly,the loss factor is independent of the relaxation time distribution ofthe substance being investigated, if the displacement is caused by auniform motion with a constant scalar velocity v, the loss factor vectoris a function of v only (i.e., a single variable). Therefore, velocity vmay be determined from the loss factor vector λ{circumflex over ( )}(vectors herein are denoted with the character “{circumflex over ( )}”)This requires that several measurements be made with varying velocities.Let the measured response vector be S_(v){circumflex over ( )}={A₁, . .. , A_(n)} and assume a measured response, such as for v=0, produces aresponse vector S₀{circumflex over ( )}={A⁰ ₁, . . . , A⁰ _(n)}, thenthe characteristic loss factor vector is directly given by λ{circumflexover ( )}={A₁/A⁰ ₁, . . . , A_(n)/A⁰ _(n)}. Thus, for a givenmeasurement apparatus with known field maps and a fixed pulse sequence,a lookup table of λ{circumflex over ( )}(v) can be calculated from whichv can be derived.

The methods and apparatus of the present invention utilize an excitationpulse in accordance with field maps B_(O) and B₁ that cause theresonance region where spins are excited by the pulse to have a specificshape. The specific shapes are selected depending on the generaldirection of fluid flow that is being measured. For example, if radialflow is an important component of a desired measurement, the NMR toolused in flow velocity measurement is configured such that a thin, long,cylindrically-shaped resonance region is defined. A cylindrically-shapedresonance region is essentially unaffected by vertical displacements(such as, for example, vertical movement of logging drill string 114),while being especially sensitive to radial movement. It can be created,for example, using an axisymmetric gradient design for B₀ like thatemployed in the MRIL® tool of the Numar Corporation.

On the other hand, if vertical displacement is an important factor, theNMR tool may be configured to provide a resonance region that isessentially a flattened torus-shape (like a flattened doughnut). Aflattened torus-shaped resonance region, which is especially sensitiveto vertical displacement, may be created, for example, by using aJasper-Jackson saddle point design and tuning the operating frequenciesabove the Larmor frequency at the saddle point (see U.S. Pat. No.4,350,955). When both radial and vertical displacement are importantparameters, two separate NMR tools, such as tools 104 and 108 of FIG. 1,may be utilized. Under such circumstances, NMR tool 104 may beconfigured to form a cylindrically-shaped resonance region, while NMRtool 108 may be configured to form a flattened torus-shaped resonanceregion. Additionally, if a gradient B₁ field is present, it is alsopossible to utilize a saddle-point-shaped B_(O) at resonance.

In addition to determining flow velocity v from the loss factor λ_(i),it is also possible to determine flow velocity by analyzing the echoshape in either the frequency or time domain. Or, the fact that flowcauses the phases of the echoes to shift in the x-y plane (of theconventional NMR “rotating” coordinate system) can be utilized tocharacterize the motion and further enhance resolution. The correctionvector λ{circumflex over ( )}(v), thus can be determined solely byquantitative analysis of the recorded echo phases and echo shapes in thetime domain or frequency domain and knowledge of the T₂ distribution isnot required. In the case of a monotonic gradient G, it is possible toobtain information about the flow direction by qualitative analysis ofthe echo shape.

As described above, FIG. 1 shows one embodiment of an NMR logging device100 that includes two NMR tools 104 and 108, each being configured tomeasure a different aspect of flow velocity. As NMR tool 104 isconfigured to measure radial displacement, its resonance region isillustrated by resonance lines 118, while resonance lines 120 illustratethe vertically oriented resonance region of NMR tool 108 (note that flowlines 116 pass through resonance lines 118 and 120). In addition,packers may be used to create a specific flow path. For example, FIG. 1shows NMR tool 104 between packers 102 and 106 in an isolated portion ofwellbore 110. Packers 102 and 106 utilize expansion components 122 and124, respectively, to effectively seal off a portion of the wellbore.Then, NMR tool 104 induces fluid flow by drawing fluid from the wellboreinto the tool itself through a fluid inlet port. This creates a localpressure change in the isolated area which induces a flow of fluid inthe formation (shown in FIG. 1 by flow lines 116).

FIGS. 2a, 2 b, 3 a, and 3 b show embodiments of NMR tool components thatmay be used in accordance with the principles of the present inventionto measure flow velocity, either in conjunction with the NMR tools ofFIG. 1, or other NMR tool configurations. The NMR tool components ofFIGS. 2a, 2 b, 3 a, and 3 b, as well as the NMR tool components shown inFIG. 4 also include the capability to provide pressure measurements whenpressed against the wall of the wellbore (contrary to the device shownin FIG. 1 that is held away from the wellbore wall by packer modules).Moreover, while the fields of the device shown in FIG. 1 are axiallysymmetric, the fields of the NMR tool components of FIGS. FIGS. 2a, 2 b,3 a, 3 b, and 4 are not.

FIGS. 2a and 2 b show one embodiment of an NMR tool pad 200 that couldbe used on NMR tool 108, NMR tool 504 (describe below) or in other NMRtool configurations not shown. Pad 200 includes back-up plate 202,sealing element 204, and pressure monitor probes 206. Additionally,resonance region 208, which is similar to resonance lines 120 of FIG. 1(but, contrary to resonance lines 120, are not axially symmetric),illustrates the sensitivity to motion along an imaginary line joiningthe pressure probes 206 (of FIG. 2a). If used with logging device 100,pad 200 would actually be rotated 90° so that resonance region 208conforms with resonance lines 120. Moreover, in order to utilizepressure monitor probes 206, pad 200 must be configured such that it isplaced against the wellbore wall (see, for example, the NMR toolconfiguration shown in FIG. 5 and the corresponding text below) andhydraulic communication is made between probes 206 and the formation.

FIGS. 3a and 3 b show another embodiment of an NMR tool pad 300 thatcould be used on NMR tool 108, NMR tools 400 and 500 (described below)or on a single NMR tool (not shown) that is configured to produce twodifferent resonance regions (i.e., vertical and horizontal). Pad 300includes back-up plate 302, sealing element 304, pressure monitor probes306 that measure pressure azimuthal gradients 316, pressure monitorprobes 312 that measure elevational gradients 322 and fluid inlet port314 that draws fluid into the logging device. Additionally, resonanceregion 308 illustrates the sensitivity to radial motion, while resonanceregion 318 illustrates the sensitivity to vertical motion. It should benoted that, because a pressure sensor is not placed into the formation,the radial component of the pressure drop is not measured. Assuming thatthe formation is isotropic in the horizontal plane, then the radialpermeability component is substantially similar to the azimuthalcomponent. Thus, obtaining an azimuthal measurement via probes 306provides a radial answer.

It should be noted that, in accordance with the principles of thepresent invention, the shaped resonance regions are not limited simplyto cylinders and flattened-toroids, and that the tools described aboveare merely illustrative of how the present invention may be applied tosuch devices. For example, the pads of FIGS. 2a and 3 a are generallysensitive to motion in the circumferential direction, i.e., rotation ofthe drill string within the borehole. Thus, the present invention may beutilized to produce specific-shaped resonance regions that aresubstantially smaller in one direction than any other direction, andthat the smaller direction is beneficial because it providesmeasurements that essentially are unaffected by movement in thatdirection. For example, the thin, long, cylindrically-shaped region isgenerally unaffected by vertical movement.

FIG. 4 shows another embodiment of a logging device 400 that may be usedin accordance with the principles of the present invention. Rather thanutilize a single pad 300 to perform a wide variety of functions (whichaccordingly increases the complexity and expense of producing such apad), device 400 offers an alternative when used in conjunction with,for example, pad 200 of FIG. 2a. Device 400 includes pressure monitorprobes 402, 404 and 406, another NMR tool (not shown) and a fluidsampling probe 408 that is used to sample formation fluid instead offluid inlet port 314 of pad 300 (see FIG. 3a).

Device 400 has multiple applications. First, NMR probes 402, 404 and 406may be utilized to obtain a small-scale permeability measurement (inboth vertical and horizontal directions) of the invaded zone, i.e., thezone of the formation affected by drilling damage. Second, probes 406and 408 may be used to perform a “deeper” permeability measurement byconducting a pressure interference test between the probes (provided thespacing between probes 406 and 408 is sufficiently large). Probe 408would be used to create a pressure pulse by withdrawing fluid into theprobe. A comparison of the two different permeability measurements(i.e., the small-scale or invaded zone measurement, and the “deeper” orvirgin reservoir) provides information on the formation heterogeneity.In addition, if the extent of the damaged zone is available, forexample, from an array resistivity log, then a value of the “skin” alsomay be determined.

Persons skilled in the art will appreciate that, although three specificconfigurations of logging tools have been described, that there arecountless other combinations that may be used to practice the principlesof the present invention. For example, a fifth probe could be placedopposite probe 402 on device 400. In such a configuration, probes 404,406 and 408 may be of the type shown in FIG. 3a, while probes 402 andthe fifth probe may be of the type shown in FIG. 2a. Device 400 alsowould have the capability to determine permeability using the pressureinterference test while determining small-scale permeability using theNMR techniques described herein.

FIG. 5 shows a schematic illustration of another embodiment of thepresent invention in which an NMR logging device 500 measures localpressure gradients so that parameters such as permeability and skindamage may be determined. Logging device 500 includes an NMR tool 504and packers 506 and 508. Packers 506 and 508 operate as described aboveto create a specific flow path within the earth formation. NMR tool 504includes pressure sensor 530 and NMR tool pads 534 and 536, each ofwhich may be similar to the NMR tool pads described above. For example,NMR tool pad 534 may be used to form resonance region 518 in theformation surrounding wellbore 510. More importantly, NMR tool 504 alsoincludes moveable springs 532 that press pressure sensor 530 againstwellbore wall 511 so that local pressure gradient measurements may beobtained.

To determine the skin damage, probes 534 and 536 determine thesmall-scale permeability (i.e., local permeability of the damaged zone).Fluid then is flowed into the region between packer modules 506 and 508,which breaks the mudcake seal, to induce a large pressure pulse. Thepressure pulse is used to perform an interference test between thepacker probe and another probe (not shown) located outside the packerregion. Persons skilled in the art will appreciate that the small-scaleNMR permeability measurement must be made prior to breaking the mudcakeseal and the interference test when utilizing device 500. Moreover, withthe addition of a pressure gauge (not shown) located between packermodules 506 and 508, device 500 also may be utilized for thedetermination of skin and formation pressure.

When formation pressure is being determined, packer modules 506 and 508are utilized to isolate a portion of the wellbore. NMR probe 504 isutilized to produce resonance shell 518 that is used to sense when thereis no mud filtrate invasion into the formation—that filtrate fluid speedis zero. Pressure monitor probe 530 senses the pressure on the otherside of the mudcake from the wellbore, while another pressure sensor(not shown) located between the packers monitors the pressure in thepacker interval. Fluid is then withdrawn or injected until a zero fluidspeed condition exists, at which point the pressure in the packerinterval should be the same as the formation pressure.

The methods of quantitative interpretation are simplified when a uniformgradient field is present because in a uniform gradient G{circumflexover ( )}, the relationship between a displacement vector r{circumflexover ( )}(t) and a change in resonance frequency δω also is a functionof one parameter: G{circumflex over ( )}·r{circumflex over ( )}=δω.Therefore, every change in resonance frequency corresponds to aparticular displacement and δω_(i) at the time I*t_(e) of echo I can berelated to an average velocity r/(I*t_(e)). Every echo I of a given echotrain thus represents an experiment with a different “mixing” time(I*t_(e)) in the sense of the standard NMR exchange experiments.However, the signal-to-noise ratio can be enhanced by using all of theechoes together to extract velocity.

For example, an analysis of the echo shape f(t) (or echo spectrum f(ω))only provides information regarding where the sum of the spins moved,but does so in a fast and efficient manner so that few NMR experimentsare needed. If more information is required, such as a determination ofwhere each spin is moving, frequency selective experiments (eitherone-dimensional or two-dimensional) may be performed, but suchexperiments are more demanding in terms of measurement time and thenumber of measurements required. As a variation from the previouslydescribed NMR techniques, this embodiment of the present inventionrequires that the spins be marked or labeled in dependence of theirresonance frequency by applying RF pulses either immediately before orafter the excitation pulse. The simplest way of marking would be asaturation sequence that creates a resonance frequency dependentsaturation pattern. A measurement of velocity may then be obtained bycorrelating resonance frequency at two different times.

FIGS. 6a-6 e show various schematic examples of two-dimensional exchangespectra of the I-th echo. FIG. 6a shows a two-dimensional distribution602 for the I-th echo in the absence of displacement and translationaldiffusion. FIG. 6b shows a two-dimensional distribution 604 for the I-thecho that indicates the influence of strong diffusion (or statisticaldisplacement). FIG. 6c shows a two-dimensional distribution 606 that isthe result of displacement occurring in the lower field with a givenvelocity v. FIG. 6d shows a similar two-dimensional distribution 608that results from motion having the same velocity, but oppositedirection (i.e., into the high field). Finally, FIG. 6e shows the resultof doubling the velocity shown in FIG. 6d (the result would be the samewhether velocity (v), “mixing” time (I*t_(e)) or echo number (2*I) weredoubled). FIGS. 6a-6 e show that, in this embodiment, only frequencydisplacement affects the determination of flow velocity (versus decayamplitude as described above). Persons skilled in the art willappreciate that the data shown in FIGS. 6a-6 e, without encoding (i.e.,just measuring echo shape) would appear as curved projections instead ofspectra, as shown by way of illustration in FIG. 6e by dashed linecurves 612 and 614. Similar projections also could be produced for eachof FIGS. 6a-6 d, if desired.

FIG. 7 shows a flow diagram that illustrates the methods of the presentinvention for determining flow velocity. In a step 702, the tool isplaced in the wellbore (depending on exactly which tool and the desiredparameters, step 702 may be performed as part of drilling operations orit may be performed separate from drilling operations, for example, whenlocal gradient pressure measurements are necessary). Fluid is induced toflow in a step 704 in any known manner. For example, via externalpumping using equipment from the top of the borehole or by utilizingpumping ports on the well logging tool itself, as shown in FIG. 3a(i.e., fluid inlet port 314).

A strong, polarizing, static magnetic field is applied to the formationin a step 706, through the use of, for example, permanent magnets, thatpolarizes a portion of the formation (i.e., longitudinal magnetization).An oscillating magnetic field then is applied in a step 708 inaccordance with field maps B_(O) and B₁ to produce a resonance regionhaving a specific shape dictated by the desired motion sensitivity. Theoscillating magnetic field is the result of the application of a seriesof RF pulses to the formation which forms a resonance region. Thespecific shape of the resonance region, which is determined by thespecific sequence of RF signals, is chosen depending on the desired axisof sensitivity. For example, a thin, long, cylindrically-shapedresonance region may be produced for measurements that require minimalimpact by vertical displacement of the drill string.

The sequence of applied RF pulses excites specific nuclear spins in theformation that induce a series of spin echoes. The spin echoes inducedby the oscillating magnetic field are measured in a step 710. The decayloss factor is determined in a step 712 (e.g., if there is no movement,the decay loss factor will be unity). Finally, the flow velocity isderived, in a step 714, from the decay loss factor. Persons skilled inthe art will appreciate that other parameters, such as permeability,require additional steps not shown in FIG. 7 (for example, in order todetermine permeability, a step of measuring local pressure gradientsmust be added).

One advantage of the change in resonance frequency measurement of flowvelocity is that, for identical conditions, the resonance frequencymeasurement provides detection of much smaller displacement velocitiescompared to the decay amplitude embodiment previously described.However, the frequency selective analyses (both one-dimensional andtwo-dimensional) require the presence of a uniform gradient field thatis not a requirement of the echo shape and decay analysis. Thus, undercircumstances where a uniform gradient exists and very thick resonanceregions are required, resonance frequency measurements may beparticularly advantageous. Moreover, the spread in displacement could beanalyzed in terms of free fluid, bound fluid, viscosity or theinteraction of the fluid with the rock surface to provide additionalinformation about the formation and the fluids present therein.

Many of the previously described NMR measurements of flow velocity relyon a relatively high gradient in B_(O). Therefore, those measurementtechniques are not useful under circumstances where saddle-pointmeasurements need to be made. A saddle-point tool can be used to measureflow velocity, however, a gradient in the pulse amplitude B₁ is present.There are various known techniques for applying magnetic field gradientsto produce stimulated echoes, however, those techniques all require aninhomogeneous B₁ encoding pulse followed by the application of ahomogeneous B₁ refocusing pulse and homogeneous B₁ reading pulses.Inside out NMR saddle-point tools naturally produce the requiredstrongly inhomogeneous B₁ field (from the RF coil), but thesubstantially homogeneous B₁ field simply is not achievable.

The refocusing/reading pulse may, in accordance with the presentinvention, be accomplished with the inhomogeneous B₁ field by utilizingadiabatic methods as shown in FIG. 8. For example, following encodingpulse 802 (that spirals the spins between the longitudinal and atransverse direction), a series of adiabatic refocusing pulses (AFP) 804are applied to create an echo train. The echo train is then spooled backby applying a negative encoding pulse 806 to decode the echo train.Then, excitation may be performed adiabatically by applying an adiabaticfast half passage pulse (AHP) 808 into the resonance zone just prior tothe application of detection sequence 810.

Detection sequence 810 may be accomplished by applying an adiabatic fasthalf passage pulse into the resonance zone—starting at a frequencyoutside of the resonance zone, varying the frequency of the refocusingpulse so that it sweeps through the entire resonance zone, and stoppingat the resonance frequency. Alternately, the B_(O) field may be variedinstead of the frequency. In addition, if diffusion is present, itseffects may be suppressed by applying a multi-echo sequence with manyrefocusing pulses, such as refocusing pulse sequence 804, to introducephase errors that cancel themselves out when an even number ofrefocusing pulses are applied. For the detection sequence, a single echoor a multi-echo train may be utilized. Effective excitation may beprovided by an adiabatic pulse by applying an adiabatic half passagepulse to turn the spins into the transverse plane.

The capability to measure flow velocity provides additional advantages.For example, NMR apparatus may be installed within a drill string andoperated during a pause in drilling operations to provide immediatefeedback. One particularly useful parameter that may be determined is adirect measurement of permeability based on Darcy's formula whichstates: $\begin{matrix}{v = {\frac{1}{\mu}K*{grad}*p}} & (3)\end{matrix}$

where v represents seepage velocity, μ represents fluid viscosity, Krepresents the permeability (tensor) and p is the local value of thefluid pressure. In earth formations at the scale of the measurementsaddressed herein, the permeability K is essentially determined by twoindependent values K_(h) and K_(v) (i.e., the horizontal component andthe vertical component, respectively).

By applying the NMR measurements described above to determine localfluid velocity, values for K_(h) and K_(v) may be directly obtained(provided that probes are set to measure local pressure gradients, suchas the configurations shown in FIGS. 4 and 5). For example,K_(v)=μv_(z)/dp/dz. Assuming the fluid viscosity μ is known, dp/dzeasily may be obtained through the use of pressure monitor probes, andbecause v_(z) is determined based on one of the above-described NMRmeasurements, K_(v) can be determined. If it is assumed that thepermeability is isotropic in the transverse plane, then an azimuthalmeasurement of the pressure gradient utilizing pressure monitor probesand a measurement of fluid velocity (as described above) provides K_(h)(based on the derivation that K_(h)=μv_(θ)r_(w)/dp/dθ). Once K_(h) andK_(v) are determined, permeability K is also determined, in this case insitu. However, it should be noted that, as described above, becauselocal pressure gradient measurements can not be obtained during drillingoperations (because the sensor probes must be placed against thewellbore wall), neither can permeability measurements be made duringdrilling operations.

Another parameter that may be determined using the flow velocitymeasurements of the present invention is an assessment of drillingdamage (i.e., the alteration of permeability into the formation a radialdistance r_(d) due to drilling operations). This assessment may bedetermined by determining the additional pressure drop or “skin” Sassociated with the altered region of the formation when fluid flowsinto the wellbore (as this assessment also relies on a measurement oflocal pressure gradient, it also cannot be performed during drillingoperations). The determination of S is based, at least in part on thepermeabilities of the virgin formation and the damaged formation. Thus,skin S may be calculated as follows: $\begin{matrix}{S = {\left( {\frac{K_{\infty}}{K_{d}} - 1} \right){\ln \left( \frac{r_{d}}{r_{w}} \right)}}} & (4)\end{matrix}$

where r_(w) is the wellbore radius, and K_(∞) and K_(d) are thepermeabilities of the virgin formation and damaged zones, respectively.Accordingly, once r_(d) is determined from for example, arrayresistivity logs, a detailed, depth-resolved model of the damaged zonecan be constructed and a value of the skin may be determined.

It is also possible to take measurements of formation pressure, however,such measurements, as explained above, also cannot be taken whiledrilling is active. Formation pressure may be measured by applying thevelocity measurement principles described above, and detecting thecondition when the formation fluid is at rest (i.e., motionless). Thismay be accomplished by manipulating the wellbore pressure whilemonitoring the measured velocity. When the measured velocity is zero,the local pressure at the test depth must be equal to that of theformation (such that no fluid flows either from the wellbore into theformation (i.e., invasion), or vice versa). At that instant, the mudpressure, which can be determined using conventional tools, is anaccurate measure of the formation pressure.

It should be recognized that it may be difficult to determine the zerovelocity condition, because resolution decreases at low velocities. Inthat case, formation velocity could be measured while adjusting wellborepressure in discrete steps. A plot of the measured velocity as afunction of local wellbore pressure may be extrapolated to determine thepressure at which zero velocity would occur. While nonlinearities in themudcake transmissivity may be manifested in the pressure-velocityrelationship, such steps may be necessary where it is prohibitive toreduce the well pressure well below formation pressure.

When, for reasons of well control, safety or precision in measurement,it is desirable to adjust the pressure in the entire wellbore, the localformation pressure may be determined by the application of principlesshown in FIG. 5, as described above. An NMR experiment to measureformation pressure could be conducted using a three module loggingdevice where a radially sensitive NMR tool is located between two packermodules (as shown by modules 504, 506 and 508). The packer modules 506and 508 could isolate a portion of the wellbore 510 and NMR module 504could include a pumpout unit that would inject and/or extract fluidinto/from the isolated interval in order to adjust the pressure in theisolated portion of the wellbore. A conventional pressure probe 530 alsocould be utilized within the packer interval that directly measures thepressure of the sandface interface (i.e., the interface between themudcake and the formation) in order to accurately determine thetransmissivity of the mudcake. Such techniques may not be suitable forlow permeability formations where steady pressure conditions may not beachievable in the time period allocated for testing.

The development of the mudcake itself is another important parameterthat may be determined in accordance with the NMR measurements ofvelocity described above. It is important to be able to determine therate of loss of mud filtrate into the formation (i.e., invasion), whichis an accurate indicator of the overall quality of the mud system beingemployed. Mud filtration rate may be determined by integrating fluidflow measurements over a cylindrical surface concentric with thewellbore. The result is a direct measurement of the volumetric flux ofthe invading fluid provided that near steady-state conditions arepresent (for example, the rate at which mud filtrate invades theformation should be substantially constant). Thus, this parameter alsocannot be determined while drilling is occurring.

We claim:
 1. A method of measuring formation pressure of an earthformation utilizing at least one nuclear magnetic resonance (NMR) toolplaced in a wellbore in the formation, the wellbore being at a wellborepressure and having an annular mudcake at a pressure between the NMRtool and the formation, the method comprising: measuring the pressure ofthe wellbore as a function of time; inducing fluid to flow; applying astatic magnetic field from the NMR tool to a volume of the formation,the static magnetic field polarizing a substantial portion of theformation that is subject to the static magnetic field; applying anoscillating magnetic field to a specific part of the polarized portionto induce the production of measurable signals, the oscillating magneticfield being applied in accordance with field maps B_(O) and B₁ toproduce a resonance region having a thin, long cylindrical shell-shapethat is sensitive to radial flow; measuring the induced signals;deriving a horizontal component of flow velocity from the measuredsignals; monitoring the derived flow velocity while varying wellborepressure until a zero velocity condition is obtained; and providing thewellbore pressure when zero velocity occurred as the measure offormation pressure.
 2. The method of claim 1, wherein formation pressurefor a particular zone of the formation is determined by creating aspecific flow path in the particular zone between a pair of first andsecond packer modules, the NMR tool being located between the first andsecond packer modules.
 3. The method of claim 2, further comprising:utilizing a pressure measurement probe between the first and secondpacker modules to provide a pressure measurement at an interface betweenthe mudcake and the formation; determining transmissivity of the mudcakebased on the pressure measurement probe measurement, the wellborepressure measurement and the horizontal component of flow velocity.
 4. Amethod of measuring formation pressure of an earth formation utilizingat least one nuclear magnetic resonance (NMR) tool placed in a wellborein the formation, the wellbore being at a wellbore pressure and havingan annular mudcake at a pressure between the NMR tool and the formation,the method comprising: measuring the pressure of the wellbore as afunction of time; inducing fluid to flow; applying a static magneticfield from the NMR tool to a volume of the formation, the staticmagnetic field polarizing a substantial portion of the formation that issubject to the static magnetic field; applying an oscillating magneticfield to a specific part of the polarized portion to induce theproduction of measurable signals, the oscillating magnetic field beingapplied in accordance with field maps B_(O) and B_(l) so that aresonance region having a specific shape corresponding to a desiredsensitivity is formed in the formation; measuring the induced signals;deriving a horizontal component of flow velocity from the measuredsignals; monitoring the derived flow velocity while varying wellborepressure until a zero velocity condition is obtained; and providing thewellbore pressure when zero velocity occurred as the measure offormation pressure.
 5. The method of claim 4, wherein the desiredsensitivity corresponds to radial flow and the shape is a thin, longcylindrical shell.
 6. The method of claim 4, wherein the measurement ofthe induced signals comprises: measuring amplitude of the inducedsignals.
 7. The method of claim 4, wherein the induced signals areproduced from spin echoes, each having an echo shape and phase, themethod further comprising: determining flow direction by quantitativelyanalyzing the echo shapes in frequency domain.
 8. The method of claim 4,wherein the induced signals are produced from spin echoes, each havingan echo shape and phase, the method further comprising: determining flowdirection by quantitatively analyzing the echo shapes in time domain. 9.The method of claim 4, wherein the resonance region issaddle-point-shaped.
 10. The method of claim 4, wherein the desiredsensitivity includes radial and applying the oscillating magnetic fieldcomprises: applying via a NMR tool a first oscillating magnetic field,the first oscillating magnetic field being applied in accordance withspecific field maps B_(O) and B_(l) so that a resonance region having athin, long cylindrical shell shape is formed in a first specific part ofthe polarized portion to induce the production of measurable signalsthat are sensitive to radial flow.
 11. The method of claim 4, furthercomprising distinguishing diffusion from induced fluid flow.
 12. Themethod of claim 4, wherein applying an oscillating magnetic fieldcomprises: applying a sequence of refocusing pulses that induce spinechoes to be produced, the spin echoes corresponding to the measurablesignals.
 13. The method of claim 12, wherein the sequence of refocusingpulses is applied in accordance with a CPMG pulse sequence.
 14. Themethod of claim 4, wherein formation pressure for a particular zone ofthe formation is determined by creating a specific flow path in theparticular zone between a pair of first and second packer modules, theNMR tool being located between the first and second packer modules. 15.The method of claim 14, further comprising: utilizing a pressuremeasurement probe between the first and second packer modules to providea pressure measurement at an interface between the mudcake and theformation; determining transmissivity of the mudcake based on thepressure measurement probe measurement, the wellbore pressuremeasurement and the horizontal component of flow velocity.
 16. A methodof measuring formation pressure of an earth formation utilizing at leastone nuclear magnetic resonance (NMR) tool placed in a wellbore in theformation, the wellbore being at a wellbore pressure and having anannular mudcake at a pressure between the NMR tool and the formation,the method comprising: measuring the pressure of the wellbore as afunction of time; inducing fluid to flow; applying a static magneticfield from the NMR tool to a volume of the formation, the staticmagnetic field polarizing a substantial portion of the formation that issubject to the static magnetic field; applying an oscillating magneticfield to a specific part of the polarized portion to induce theproduction of measurable signals, the oscillating magnetic field beingapplied in accordance with field maps B_(O) and B_(l) to produce aresonance region having a thin, long cylindrical shell-shape that issensitive to radial flow; measuring the induced signals; deriving ahorizontal component of flow velocity from the measured signals;measuring at least two wellbore pressure values while varying wellborepressure; calculating a zero velocity condition based on the measuredflow velocity; and calculating a wellbore pressure associated with thecalculated ero velocity condition.
 17. The method of claim 16, whereinformation pressure for a particular zone of the formation is determinedby creating a specific flow path in the particular zone between a pairof first and second packer modules, the NMR tool being located betweenthe first and second packer modules.
 18. The method of claim 17, furthercomprising: utilizing a pressure measurement probe between the first andsecond packer modules to provide a pressure measurement at an interfacebetween the mudcake and the formation; determining transmissivity of themudcake based on the pressure measurement probe measurement, thewellbore pressure measurement and the horizontal component of flowvelocity.